This invention relates to the real time, in situ monitoring of fluids, and especially to the determination of contaminants in a fluid infrastructure. The invention is directed in particular to the detection of hydrogen sulfide in a natural gas transmission line, but aspects of the invention may be employed to detect other contaminants in other environments as well.
Natural gas is a mixture primarily of methane (CH4) and other hydrocarbons plus carbon dioxide (CO2), nitrogen (N2), hydrogen sulfide (H2S) and water (H2O). The hydrogen sulfide component is an extremely toxic and irritating gas, causing eye irritation, dizziness, coughing, and headaches at low concentrations and unconsciousness or death at higher concentration if released into the local environment. In addition to its adverse human health effects, the presence of hydrogen sulfide in natural gas can cause sulfide stress cracking and hydrogen-induced cracking to the lines through which the gas is transmitted. Consequently, most natural gas processing facilities treat natural gas to neutralize the hydrogen sulfide, so it is important to accurately measure the amount of hydrogen sulfide present so that appropriate amounts of chemical neutralizer may be added. For these and other reasons, it is important to be able to accurately detect the amount of hydrogen sulfide in the system during transmission.
Near infrared (NIR) spectrographic analysis is the preferred method for determining the composition of natural gas because, unlike with gas chromatography, there is no need for calibration gases, carrier gases or filters to perform measurements. The measurements are made at the operating temperature and pressure of the fluid infrastructure without the need to extract and alter a representative sample, thereby minimizing the possibility of sample contamination and the risk of analyzing material that is not truly representative of the fluid in the process line. Also, the presence of liquid condensate in the gas stream cannot be measured by a gas chromatography system, but can be detected by an NIR spectrometer.
Near-infrared spectroscopy generally operates in the 1350 to 2500 nanometer (nm), or 1.35 to 2.5 micrometer (μm), wavelength region. The strongest absorption frequencies of most hydrocarbon gases fall between 1600 and 1800 nm, while the NIR absorption spectra of hydrogen sulfide falls between approximately 1570 and 1610 nm. Though this absorption band for hydrogen sulfide is relatively weak, it nevertheless means that NIR spectroscopy is an excellent candidate for both determining the energy content of the natural gas and determining the degree to which hydrogen sulfide is present.
Unfortunately, determining the amount of hydrogen sulfide in situ in a natural gas stream under pressure is extremely difficult. Hydrogen sulfide is a very weak NIR absorber and, as a result, the signal-to-noise ratio is very low. This is complicated by the fact that there are species of hydrocarbons in natural gas whose absorption frequencies may interfere with hydrogen sulfide's absorption frequency, most notably methane (CH4) and carbon monoxide (CO), but in some cases also some of the larger alkane molecules such as propane (C3H8). Finally, because absorption lines broaden with increasing pressure and temperature, hydrogen sulfide analysis with tunable diode lasers that are only capable of creating a very narrow range of NIR excitation frequency and focus on a single absorption peak is restricted to a certain maximum pressure and process temperature.
There is a need, therefore, for a method and system for using NIR spectroscopy in situ, under operating pressure, and in real time to reliably detect both the energy content of a fluid as well as the presence of trace quantities of hydrogen sulfide in the fluid. This system must be able to detect multiple absorbance bands of the hydrogen sulfide molecule over the high resolution scan and be able to distinguish these from the other peaks in the region.